U.S. patent application number 13/018325 was filed with the patent office on 2011-05-26 for method and system for monitoring the incursion of particulate material into a well casing within hydrocarbon bearing formations including gas hydrates.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to AHMED H. AL-JUBORI, BRIAN W. CHO, MASAFUMI FUKUHARA, SHUNETSU ONODERA, HITOSHI SUGIYAMA.
Application Number | 20110120703 13/018325 |
Document ID | / |
Family ID | 44061246 |
Filed Date | 2011-05-26 |
United States Patent
Application |
20110120703 |
Kind Code |
A1 |
ONODERA; SHUNETSU ; et
al. |
May 26, 2011 |
METHOD AND SYSTEM FOR MONITORING THE INCURSION OF PARTICULATE
MATERIAL INTO A WELL CASING WITHIN HYDROCARBON BEARING FORMATIONS
INCLUDING GAS HYDRATES
Abstract
A method and system for monitoring any incursion of particulate
matter from a gas hydrate formation into a well casing used for the
production of the gas hydrate and determining the degree of
incursion of particulate material within the distal end of the well
casing.
Inventors: |
ONODERA; SHUNETSU; (GLOS,
GB) ; SUGIYAMA; HITOSHI; (SURREY, GB) ; CHO;
BRIAN W.; (CUMBRIA, GB) ; AL-JUBORI; AHMED H.;
(ALBERTA, CA) ; FUKUHARA; MASAFUMI; (MOSCOW,
RU) |
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
Sugar Land
TX
|
Family ID: |
44061246 |
Appl. No.: |
13/018325 |
Filed: |
January 31, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
11612494 |
Dec 19, 2006 |
7886820 |
|
|
13018325 |
|
|
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Current U.S.
Class: |
166/250.01 |
Current CPC
Class: |
E21B 41/0099 20200501;
E21B 43/08 20130101; E21B 23/02 20130101; E21B 43/119 20130101 |
Class at
Publication: |
166/250.01 |
International
Class: |
E21B 47/00 20060101
E21B047/00 |
Claims
1. A system for determining the degree of incursion of particulate
matter into a well casing used in the production of gas from a
subterranean gas hydrate formation, said system comprising: a
distributed temperature sensing system connected to the end of a
submersible pump positioned within the well casing for pumping gas
and water out of the well casing and extending within the well
casing toward the distal end of said well casing, wherein measuring
the thermal characteristics of the surrounding material beneath the
submersible pump at the end of the well casing, the position of a
fluid to particulate material interface may be estimated.
2. A system for determining the degree of incursion of particulate
matter into a well casing used in the production of gas from a
subterranean gas hydrate formation, said system comprising: an
acoustic transmitter connected beneath a submersible pump
positioned within the well casing for pumping gas and water out of
the well casing; an acoustic receiver connected beneath the
submersible pump positioned within the well casing, wherein
observing the waveform of the sound generated by said transmitter
and received by said receiver, the interface between a fluid and
particulate material within the well casing may be estimated.
3. A system for determining the degree of incursion of particulate
matter into a well casing used in the production of gas from a
subterranean gas hydrate formation, said system comprising: a
vibrator connected beneath a submersible pump positioned within the
well casing for pumping gas and water out of the well casing; a
vibration bar connected to said vibrator and extending toward the
distal end of the well casing, wherein observation of the vibration
mode of said vibration bar enables estimation of the interface
between fluid and particulate material within the distal end of the
well casing.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application relates to and claims the benefit under 35
U.S.C. .sctn. 119(e) of applicants' U.S. Provisional Application
Ser. No. 60/752,118 entitled "Systems and Method for Development of
Hydrocarbon Bearing Formations," filed December 20, 2005. The
disclosure of this Provisional Application is hereby incorporated
by reference as though set forth at length.
[0002] This application is a division of U.S. patent application
Ser. No. 11/612,494, filed Dec. 19, 2006.
BACKGROUND
[0003] This invention is generally related to a method and system
for monitoring the incursion of particulate matter into a well
casing that is designed for recovering hydrocarbons from
subterranean formations. In one useful aspect this invention
relates to a method and system for detecting and measuring the
buildup or accumulation of sand within a well casing operable for
producing methane gas from gas hydrate formations
[0004] A gas hydrate is a crystalline solid that is a cage-like
lattice of a mechanical intermingling of gas molecules in
combination with molecules of water. The name for the parent class
of compounds is "clathrates" which comes from the Latin word
meaning "to enclose with bars." The structure is similar to ice but
exists at temperatures well above the freezing point of ice. Gas
hydrates include carbon dioxide, hydrogen sulfide, and several low
carbon number hydrocarbons, including methane. One aspect of this
invention is the recovery of methane from subterranean methane
hydrates.
[0005] Methane hydrates are known to exist in large quantities in
two types of geologic formations: (1) in permafrost regions where
cold temperatures exist in shallow sediments and (2) beneath the
ocean floor at water depths greater than 500 meters where high
pressures prevail. Large deposits of methane hydrates have been
located in the United States in Alaska, the west coast from
California to Washington, the east coast in water depths of 800
meters, and in the Gulf of Mexico (other well known areas include,
Japan, Canada and Russia).
[0006] A U.S. Geological Survey study estimates that in-place gas
resources within gas hydrates consist of about 200,000 trillion
cubic feet which dwarfs the previously estimated 1,400 trillion
cubic feet of conventional recoverable gas reserves in the United
States. Worldwide, estimates of the natural gas potential of gas
hydrates approach 400 million trillion cubic feet.
[0007] Natural gas is an important energy source in the United
States. It is estimated that by 2025 natural gas consumption in the
United States will be nearly 31 trillion cubic feet. Given the
importance and demand for natural gas the development of new
cost-effective sources can be a significant benefit for American
consumers.
[0008] Notwithstanding the obvious advantages and potential of
methane hydrates, production of methane from gas hydrates is a
challenge for the industry. When trying to extract methane from a
gas hydrate the sequestered gas molecules must first be
dissociated, in situ, from the hydrate. There are typically three
methods known that can be used to create this dissociation.
[0009] One method is to heat the gas hydrate formation to liberate
the methane molecules. This method is disclosed in U.S. Patent
Application Publication No. US 2006/0032637 entitled "Method for
Exploitation of Gas Hydrates" published on February 16, 2006, and
of common assignment with the subject application. The disclosure
of this publication is incorporated herein by reference as
background information with respect to the subject invention.
[0010] Another method envisioned for producing methane hydrates is
to inject chemicals into the hydrate formation to change the phase
behavior of the formation.
[0011] A third technique, which is one aspect of the instant
invention, is regarded as a depressurization method. This method
involves depressurization of a gas hydrate formation and
maintaining a relatively constant depressurization on the hydrate
formation to allow dissociation and then withdrawing dissociated
gas and water through a well casing.
[0012] In all of the above mentioned techniques a well casing is
used to bring gas and fluids to the surface for separation and
processing. Sanding at the distal end of the well casing in methane
hydrate production, as well as in conventional oil and gas
recovery, will often cause a critical problem. In this, sand can
damage completion equipment and in a worst case scenario stop
production. Therefore it would be highly desirable to provide a
method and system which would be capable of estimating the movement
of the sand-fluid interface position within the well casing.
SUMMARY OF THE DISCLOSURE
[0013] There are four concepts envisioned in the subject disclosure
for addressing sanding within a production casing.
[0014] One envisioned method and system comprises installation of
two pressure sensors, below a submergible pump at the bottom or
distal end of a well casing. By measuring the pressure noise
variance between the two pressure sensors, such as phase shift or
amplitude change, the height of sand entrapped within a well casing
can be estimated;
[0015] Another method and system utilizes a continuous thermal
characteristics measurement device, such as a distributed
temperature sensing system (Hot-DTS). This unit may be installed,
for example, below the completion string. By measuring the
temperature or thermal characteristics of the surrounding material
with the temperature sensing device the position of the sand-fluid
interface may be estimated.
[0016] Further, an acoustic transmitter and receiver may be
installed at, for example, the bottom of the completion string. By
observing the waveform of the sound generated and received, the
distance between the transmitter/receiver and the sand-fluid
interface may be estimated.
[0017] Still further a vibrator and vibrating bar may be installed,
for example, below the completion string. By observing the
vibration mode of the bar, the position of the sand-fluid interface
may be estimated.
THE DRAWINGS
[0018] Other features and aspects of the disclosure will become
apparent from the following detailed description of some
embodiments taken in conjunction with the accompanying drawings
wherein:
[0019] FIG. 1 is a pictorial view of one context or geological
region of permafrost in Alaska where gas hydrates are know to
exist;
[0020] FIG. 2 is a pictorial view of another context or geological
region of gas hydrates beneath offshore regions of the United
States in water greater than 500 meters;
[0021] FIG. 3 is a schematic representation of one technique for
producing a methane hydrate that includes a depressurization
production system including maintaining a desired level of pressure
within a well including returning water into the well from a
surface valve system;
[0022] FIG. 4 is a schematic representation of one embodiment of
the invention that includes two pressure sensors and the use of
pressure noise variance between the two sensors to estimate the
height of sand within the distal end of a well casing;
[0023] FIG. 5 is a schematic representation of another embodiment
of the invention that discloses a distributed temperature sensing
system for estimating the sand-fluid interface within a well
casing;
[0024] FIG. 6 is a schematic representation of yet another
embodiment of the invention that includes an acoustic transmitter
and receiver pair at the bottom of a completion string; and
[0025] FIG. 7 is yet another embodiment and discloses a vibrator
and vibrating bar installed below the completion string.
DETAILED DESCRIPTION
[0026] Turning now to the drawings wherein like numerals indicate
like parts, FIG. 1 discloses a pictorial representation of one
operating context of the invention. In this view a band of gas
hydrate 10 lies in a rather shallow geologic zone beneath a
permafrost layer 12 such as exists in Alaska. Other earth
formations 14 and/or aquifer regions 16 can exist beneath the gas
hydrate.
[0027] In order to recover sequestered methane gas from within the
gas hydrate zone one or more wells 18, 20 and/or 22 are drilled
through the permafrost 12 and into the gas hydrate zone 10. Usually
a casing is cemented within the well and one or more windows are
opened directly into the hydrate zone to depressurize irregular
regions of the gas hydrate represented by irregular production
zones 24, 26, 28 and 30 extending away from distal terminals of the
wells. Although a single well is shown drilled from a single
derrick illustrated at 18 and 22 it is envisioned that directional
drilling as illustrated at derrick 20 and zone 30 will be a more
common practice to extend the scope of a drilling operation.
[0028] Once one or more wells are drilled, pressure is relieved
from the gas hydrate zone around the well and the methane gas and
water molecules will separate and enter the wells. The gas can then
be separated from the water and allowed to rise to the surface or
is pumped to the surface along with water and separated and fed
along a pipeline 32 to a compressor station not shown.
[0029] An alternative operating context of the invention is
illustrated in FIG. 2 where a drillship 40 is shown floating upon
the surface 42 of a body of water 44 such the Gulf of Mexico. In
this marine environment, pressures in water depths approximately
greater that 500 meters have been conducive to the formation again
of geologic layers of gas hydrates 46, such as methane hydrates,
beneath the seabed 48.
[0030] Offshore drilling in water depths of 500 meters or more is
now technically possible so that drilling into the offshore gas
hydrate formations 46 and cementing a casing into a well hole
offshore to form a production strata 50 is another source of
production of methane from a gas hydrate formation. Again,
directional drilling from a subsea template enables fifty or more
wells to be drilled from a single drillship location,
[0031] Turning now to FIG. 3, there will be seen one method and
system in accordance with one embodiment of the invention. In this,
a well hole 60 is drilled through an earth formation 62 and into a
previously identified geologic layer of methane hydrate 64. A
casing 66 is positioned within the well and cemented around the
outer annulus for production. At a selected depth, which may be
relatively shallow for drilling through permafrost or deep if
offshore, the casing is perforated by one or more windows 68 which
establish open communication between the interior of the well
casing and a zone of methane hydrate under pressure. This opening
of the well casing will relieve pressure on the surrounding methane
hydrate and will enable previously sequestered methane gas to
dissociate from the lattice structure of water molecules to form a
physical mixture of gas and water. The gas and water 70 will then
flow into the well casing 66 and rise to a level 72 within the
casing consistent with a desired level of pressure within the well
casing. In other words, the submersible pump pumps water out of the
well creating a lower hydrostatic pressure on the hydrate to
dissociate. Once the hydrate dissociates, the water and gas will
flow into the wellbore raising the water level which lowers the
drawdown pressure which then tends to prevent further dissociation.
This is a self limiting process thus the submersible pump is used
to pump out the water within the well casing to lower the water
level and to maintain the drawdown pressure necessary for
continuous dissociation. The pump creates the drawdown pressure. An
automated feedback loop maintains a constant drawdown pressure by
re-circulating some amount of produced water.
[0032] In order to recover methane gas from the mixture, the gas
and water mixture is pumped to the surface by an electro
submersible pump (ESP) 74 connected to the distal end of a first
conduit 76 extending into the well casing 66.
[0033] Some downhole pumps require a minimum amount of flow rate to
stabilize pump performance, such as an ESP. Some hydrocarbon
reservoirs do not have enough production flow, such as in methane
hydrate production wells, to efficiently use a full production ESP.
Methane hydrate production flow depends on not only formation
permeability, but also on the rate or volume of hydrate
dissociation. Accordingly, production rate may change from time to
time which may require the pump size to be changed. The present
invention endeavors to provide methods and systems that generate
the minimum flow rate of fluids for the pump by a flow back loop
that may be used to return pumped out fluid back into the well
casing to be recycled. In this, it is possible to handle a wide
range of production rates with only one large capacity downhole
pump.
[0034] At the surface the gas and water mixture passes through a
conventional gas and water separator 78 where methane gas is
separated, monitored and delivered to a pipe 80 for collection by a
compressor unit. Downstream of the separator/monitor 78 is a valve
82 to control the flow of water out of the system. Prior to
reaching valve 82 a branch or second conduit 84 is joined into the
first conduit and extends back into the well casing 66. This
enables water from the well that has been separated from the
mixture at 78 to be reintroduced back into the well casing to
maintain at least a minimum level of water 72 within the well
casing for efficient operation of the ESP 74.
[0035] Control of the volume of water reintroduced into the well
casing is provided by a choke valve 86 that is positioned within
the second conduit 84 as illustrated in FIG. 3. The position of the
choke valve can be regulated by a control line running from the
intake of the ESP to the choke valve 86. This enables the system to
maintain a constant pressure within the well casing 66 by
controlling the volume of water reintroduced into the system.
[0036] Depending upon the pressure within the well casing there may
be a tendency for the gas and water mixture to solidify within the
well casing 66, ESP 74 or first conduit 76. The temperature of
water returning to the well casing can be regulated by a
temperature control unit 90 connected to the return water or second
conduit 84 to minimize this issue.
[0037] In addition to collecting methane gas from the separator 78
methane gas is drawn directly from the top of the well casing by a
third conduit 92 that passes through a gas production monitor 94
which also delivers gas to a compressor storage system.
[0038] Depending on the downhole well casing pressure and the
pressure within the ESP 74 the gas and water mixture 70 may tend to
re-solidify during a pumping operation within the ESP intake (thus
upstream of the ESP), within the ESP 74 itself or downstream of the
ESP within the first conduit 76. In order to minimize this tendency
a fourth conduit 96 is extended within the casing 66 and is
operable to feed a chemical, such as methanol, upstream of the ESP
74, directly into the ESP or downstream of the ESP to minimize
reformation of methane hydrate within the system.
[0039] In producing methane from a gas hydrate, or other
hydrocarbon production such as conventional natural gas or oil
reserves, the production hydrocarbon flows from a subterranean
formation and into a production well casing to be pumped to the
surface for processing.
[0040] In such operations particulate material such as sand
entrained within hydrocarbon fluid streams can enter access windows
in the well casing along with the hydrocarbon for production and
settle to the bottom of the well casing. As the volume of sand
collects within the casing, efficiency of the production may be
compromised, and, accordingly sand management within a production
program is at least desirable and sometimes critical to efficient
production.
[0041] One embodiment of the disclosure for monitoring sand
build-up is disclosed in FIG. 4. In this embodiment a well casing
100 is shown cemented within a well drilled into a gas hydrate
production zone 102. The casing is fashioned with production
windows 104 that are cut or blown through the side wall of the
casing to permit ambient hydrocarbons, such as for example
dissociated methane gas and water, to enter the well casing.
[0042] Sometimes entrained with incoming pressurized hydrocarbons
and water is particulate matter such as sand 106. This relatively
heavy sand tends to fall by gravity into a lowest portion of the
well casing as illustrated in FIG. 4. Depending on the volume of
sand that accumulates the sand-fluid interface 108 may reach the
level of the well casing windows 104 and at least partially occlude
the window openings and thus impair the efficiency of the
hydrocarbon recovery.
[0043] Although techniques are know to prevent sand from entering
the well casing system, over time particulate material can
accumulate within the casing. In certain instances it has been
desirable to allow sand to enter the casing to enable the sanding
tendency in new formations. However, since there is production
equipment that can be damaged by sand, as well as decreasing well
efficiency, sand production needs to be detected and the level of
sand accumulation determined to enable an operator to take
preemptive management before the level of sand becomes
problematic.
[0044] In the FIG. 4 embodiment, a first pressure sensor 110 is
positioned at the bottom of a submersible pump 112 and a second
pressure sensor or gauge 114 is positioned near the distal end of
the well casing. Accordingly, downhole pressure at the submerged
pump level and at near the distal end of the well casing is
monitored.
[0045] In this pressure variance monitoring system of FIG. 4, a
ripple, i.e., noise, is generated in the pressure readings. If the
pressure reading is stable, the motor speed of the pump 112 is
controlled to generate noise in the pressure reading. The sand
layer 106 may be considered as a pressure filter, and the pressure
response at the bottom sensor 114 is a function of the sand column
height Ha when the well casing is vertical. Alternatively, for
lateral drilling operations the accumulation of sand and a
fluid-sand interface can be at an angle with respect to a vertical
orientation The sand column accumulation Ha may be estimated by
analyzing the noise waveform variation, such as phase shift or
amplitude variation.
[0046] Turning now to FIG. 5, a second embodiment of the disclosure
is disclosed. In this embodiment, a well casing 120 is shown
cemented into a borehole drilled into a hydrocarbon production zone
such as a gas hydrate 122. Production windows 124 are cut into the
casing to allow the flow of hydrocarbons into the well casing for
recovery. As noted above sand 126 can also enter the well casing
and collect by gravity at a lowermost location of the casing
120.
[0047] In this embodiment a continuous thermal characteristic
measurement device 128, such as a distributed temperature sensing
system (Hot-DTS), is installed, for example, below the completion
string. The DTS is a fiber optic temperature sensor that is run
within tubing 130 from the submersible pump 132 to a distal end of
the well casing 120. By measuring the temperature or thermal
characteristics, for example, thermal conductivity, of the
surrounding material with the temperature sensing device 128 the
position of the sand-fluid interface may be estimated. Methods and
systems for distributed temperature sensing are disclosed in U.S.
patent application Ser. No. 11/346,926 entitled "Systems and
Methods of Downhole Thermal Property Measurement", filed on Feb. 3,
2006, and of common assignment with the subject application. The
disclosure of this application is incorporated herein by reference
in its entirety.
[0048] The tubing or cable 130 can have a built in heater section
which can be turned on to create a more dramatic thermal
conductivity difference at the sand-fluid interface Hb.
[0049] Another embodiment of the disclosure is depicted in FIG. 6.
Here a well casing 140 is again shown cemented within a hydrocarbon
production zone 142. In this embodiment the sand-fluid interface
144 is determined by the provision of an acoustic transmitter 146
and a receiver 148 connected to the submersible pump 150.
[0050] By observing the waveform of sound generated by the
transmitter 146 and received by the receiver 148, the distance
between the transmitter/receiver and the sand-fluid interface He
may be estimated.
[0051] Turning now to yet another embodiment of the disclosure in
FIG. 7 a similar well casing 160 is shown cemented into a
hydrocarbon production zone 162. In this embodiment a vibrator 164
is connected to the base of a submersible pump 166 and a vibration
bar 168 extends from the vibrator to the distal end of the well
casing 166 and into sand 170 that has accumulated within the well
casing. By observing the vibration mode of the bar, the position Hd
of the sand-fluid interface below the vibrator 164 is estimated. In
this, the vibrating bar response system is based on the damping
factor of sand being higher than that of water. As shown in FIG. 7,
the vibration mode of the bar 168 will vary with the depth change
of the sand-fluid interface. Therefore, by observing the vibration
mode of the bar, the fluid-sand ratio may be determined, which
would indicate fluid/sand height.
[0052] In each of the above discussed embodiments a novel technique
is utilized to monitor the level of sand within a well casing so
the remedial action may be initiated as necessary or desirable.
[0053] In describing the invention, reference has been made to some
embodiments and illustrative advantages of the disclosure. Those
skilled in the art, however, and familiar with the subject
disclosure may recognize additions, deletions, modifications,
substitutions and other changes which fall within the purview of
the subject claims.
* * * * *